Sandstone stimulation using in-situ mud acid generation

ABSTRACT

A method for stimulating production of hydrocarbons from a sandstone formation includes the steps of injecting a stimulation fluid formed from a hydrofluoric acid generating precursor and an oxidizing agent, an ammonium containing compound, and a nitrite containing compound into the sandstone formation, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. The method further includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation to initiate reaction and generate heat and nitrogen gas. Upon generation of heat and degradation of the degradable encapsulation, the hydrofluoric acid generating precursor and the oxidizing agent react to form hydrofluoric acid in-situ to dissolve silica and silicate minerals and stimulate the sandstone formation. A treatment fluid for use in stimulating sandstone formations includes the stimulation fluid, the ammonium containing compound, and the nitrite containing compound.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. Non-Provisional applicationSer. No. 16/851,589 filed Apr. 17, 2020, which is a continuation-in-partof U.S. Non-Provisional application Ser. No. 16/412,962, filed May 15,2019, which is incorporated by reference herein in its entirety.

TECHNICAL FIELD

Embodiments of the present specification generally relate to stimulatingproduction of hydrocarbons from a sandstone formation, including liquidand gas wells.

BACKGROUND

Reserves trapped within certain low permeability formations, such ascertain sandstone and carbonate formations, exhibit little or noproduction, and thus may be economically undesirable to develop. Wellstimulation is one method that may be employed to increase the netpermeability of a formation or reservoir, thereby leading to increasedproduction from these wells that have little or no natural production.

During well stimulation operations, chemicals can be injected into theformation in a process known as well stimulation. Some stimulationtechniques include: (1) injection of chemicals into the wellbore wherethe chemicals react with or dissolve production-limiting deposits suchas clays, scale, and drilling solids; (2) injection of chemicals throughthe wellbore and into the formation to react with or dissolve portionsof the formation, thereby creating alternative flow paths forrecoverable hydrocarbons, such as with acid-fracturing ormatrix-acidizing processes; and (3) injection of water or chemicalsthrough the wellbore and into the formation at pressures that aresufficient to fracture the formation, thereby creating new or additionalflow channels through which hydrocarbons can more readily move from theformation into the wellbore.

Sandstone formations can be particularly susceptible to formation damagefrom formation minerals such as clay and other siliceous deposits.Stimulation methods for these types of formations have typically reliedon the use of acid or acid-based fluids for the treatment or stimulationdue to the ability of the acid or acid-based fluid to readily dissolveboth formation minerals and contaminants introduced into thewellbore/formation during drilling or remedial operations. The knownprior art techniques for stimulating sandstone reservoirs typicallyinvolve the use of mineral acids, such as hydrofluoric acid (HF) and,mud acid systems which consist of a mixture of HCl and HF, and HBF₄based systems. These systems are all corrosive and can create dangeroushandling and operating conditions. Additionally, side-reactions, such asthose described as being primary, secondary and tertiary, may lead tounwanted precipitation thereby creating formation damage as thetreatment fluid penetrates further from the near wellbore area. Further,in many instances, the reaction of the acid with the formation is rapid,frequently instantaneous, which limits the penetration depth of theacid. Further techniques for stimulating sandstone reservoirs typicallyinvolve the use organic acids, hydrolyzable esters and acid-producingenzymes.

SUMMARY

Accordingly, there continues to be a need for alternative stimulationfluids to enhance production from a sandstone formation. This primarilyrefers to a conventional sandstone formation, but may also include anunconventional formation, such as a low permeability formation like atight gas formation. Specifically, methods and compositions are neededto react deep within the formation and readily remove precipitants, suchas byproducts formed as a result of side-reactions which are formed inthe sandstone formation during reaction between the acid and theformation minerals.

According to one embodiment, a method for stimulating production ofhydrocarbons from a sandstone formation is provided. The method includesinjecting a stimulation fluid into the sandstone formation, where thestimulation fluid contains a hydrofluoric acid generating precursor andan oxidizing agent. One or both of the hydrofluoric acid generatingprecursor and the oxidizing agent comprise a degradable encapsulation.The method also includes injecting an ammonium containing compound intothe sandstone formation and injecting a nitrite containing compound intothe sandstone formation. Additionally, the method includes maintainingthe stimulation fluid, the ammonium containing compound, and the nitritecontaining compound in the sandstone formation. Maintaining thestimulation fluid, the ammonium containing compound, and the nitritecontaining compound in the sandstone formation initiates reaction of theammonium containing compound and the nitrite containing compound togenerate heat and nitrogen gas, where upon generation of heat within theformation and degradation of the degradable encapsulation, thehydrofluoric acid generating precursor and the oxidizing agent react toform hydrofluoric acid within the sandstone formation. Finally, silicaand silicate minerals are dissolved with the hydrofluoric acid tostimulate the sandstone formation.

According to another embodiment, a treatment fluid for use instimulating sandstone formations is provided. The treatment fluidincludes an ammonium-based salt, a nitrite containing compound, and astimulation fluid. The stimulation fluid contains a hydrofluoric acidgenerating precursor and an oxidizing agent, where one or both of thehydrofluoric acid generating precursor and the oxidizing agent comprisea degradable encapsulation. Further, the ammonium-based salt and thenitrite containing compound are operable to react and generate heat andnitrogen gas and the hydrofluoric acid generating precursor and theoxidizing agent react are operable to react to form hydrofluoric acid.

Additional features and advantages of the described embodiments will beset forth in the detailed description which follows, and in part will bereadily apparent to those skilled in the art from that description orrecognized by practicing the described embodiments, including thedetailed description which follows, the claims, as well as the appendeddrawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of a wellbore used for hydraulicfracturing operations.

FIG. 2 is a schematic drawing of the propagation of microfractureswithin and extending from fractures produced as a result of a hydraulicfracturing procedure.

FIG. 3 is a schematic drawing of the end view of FIG. 2 .

FIG. 4 is a schematic drawing of a sandstone formation subsequent tonitrogen gas creation in accordance with one or more embodiments off thepresent disclosure.

FIG. 5 is a graph showing the effect of initial pressure on the reactioninitiation temperature.

FIG. 6 is a graph showing the effect of pH on the reaction initiationtemperature.

FIG. 7 is a graph showing the generated heat and pressure downhole fromthe exothermic reaction of Reaction 1.

DETAILED DESCRIPTION

Reference will now be made in detail to embodiments of a method forstimulating production of hydrocarbons from a sandstone formation.

As used in this disclosure, “sandstone” refers to any formationprimarily composed of silica, silicate minerals and various forms offeldspar and days. The grains of sandstone rock are traditionallysand-sized.

Provided in this disclosure are methods and compositions for thestimulation of sandstone formations to increase well productivity. Themethods and compositions can, in certain embodiments, be utilized inconjunction with standard hydraulic fracturing and matrix acidizingtechniques. For example, the well stimulation process can involvestandard hydraulic fracturing techniques to initiate and propagate ahydraulic fracture in the referenced formation followed by introductionof the treatment fluid of the present disclosure.

The present disclosure includes a method for stimulating production ofhydrocarbons from a sandstone formation. The method includes injectingan ammonium containing compound, a nitrite containing compound, and astimulation fluid into the sandstone formation. The stimulation fluidcomprises a hydrofluoric acid generating precursor and a strongoxidizing agent. The method further includes maintaining the stimulationfluid, the ammonium containing compound, and the nitrite containingcompound in the sandstone formation to initiate reaction of the ammoniumcontaining compound and the nitrite containing compound to generate heatand nitrogen gas, where upon generation of heat within the formation thehydrofluoric acid generating precursor and the strong oxidizing agentreact to form hydrofluoric acid (HF) in-situ. Finally, the in-situformed hydrofluoric acid dissolves silica and silicate minerals in thesandstone formation to stimulate the sandstone formation.

Having described the general method for generating HF within thesandstone formation and stimulating production of hydrocarbons from thesame, attention is directed to the specific chemical constituents of thedisclosed reaction mechanism. For each of the embodiments described inthis disclosure, example hydrofluoric acid generating precursors includefluoride-containing ammonium-based salts; for example, ammonium fluoride(NH₄F) and ammonium bifluoride (NH₄HF₂). For each of the embodimentsdescribed in this disclosure, an example of a strong oxidizing agent issodium bromate. For each of the embodiments described in thisdisclosure, examples of ammonium containing compounds include ammoniumhydroxide, ammonium chloride, ammonium bromide, ammonium nitrate,ammonium nitrite, ammonium sulfate, and ammonium carbonate. For each ofthe embodiments described in this disclosure, example nitrite containingcompound include sodium nitrite or potassium nitrite.

In some embodiments, the oxidizing agent comprises any agent capable ofoxidizing an ammonium salt. In some embodiments, the oxidizing agent isan inorganic oxidizing agent. In some embodiments, the oxidizing agentcomprises an agent selected from the group consisting of a peroxide, apersulfate salt, a permanganate salt, a bromate salt, a perbromate salt,a chlorate salt, a chlorite salt, a perchlorate salt, a hypochloritesalt, a iodate salt, a periodate salt, and mixtures thereof. In certainembodiments, the oxidizing agent is a bromate salt, for instance analkali bromate salt. In certain embodiments, the oxidizing agent is orcomprises sodium bromate. In some embodiments, the oxidizing agent is anorganic oxidizing agent. In some embodiments, the oxidizing agentcomprises an agent selected from the group consisting of peracetic acidand performic acid.

In some embodiments, the oxidizing agent is present in an aqueous fluidat a concentration in the range of 0.001 M up to saturation as measuredat 20° C. In some embodiments, the oxidizing agent is present in anaqueous fluid at a concentration in the range of 0.05 M to 1.0 M, or0.05 M to 0.5 M, or 0.05 M to 0.4 M, or 0.05 M to 0.3 M, or 0.1 M to 0.3M. In some embodiments, the oxidizing agent is present in an aqueousfluid at a concentration in the range of 0.5 M to 10.0 M, or 0.5 M to9.5 M, or 0.5 M to 9.0 M, or 1.0 M to 9.0 M, or 2.0 M to 9.0 M, or 3.0 Mto 9.0 M, or 4.0 M to 9.0 M or 5.0 M to 9.0 M, or 6.0 M to 9.0 M, or 6.0M to 8.0 M, or 6.5 M to 7.5 M. In some embodiments, the oxidizing agentis present in an aqueous fluid at a concentration in the range of 1.0 Mto 4.0 M, or 1.0 M to 3.0 M, or 1.5 M to 3.0 M, or 2.0 M to 3.0 M.

In some embodiments, the oxidizing agent comprises a bromate salt suchas sodium bromate and is present in an aqueous fluid at a concentrationin a range of 0.001 M to 2.4 M. In some embodiments, the oxidizing agentcomprises sodium bromate and is present in an aqueous fluid at aconcentration in a range of 0.01 M to 2.4 M, or 0.01 M to 2.2 M, or 0.01M to 2.0 M, or 0.01 M to 1.8 M, or 0.01 M to 1.6 M, or 0.01 M to 1.4 M,or 0.01 M to 1.2 M, or 0.01 M to 1.0 M, or 0.01 M to 0.8 M, or 0.01 M to0.6 M, or 0.01 M to 0.4 M, or 0.01 M to 0.2 M, or 0.01 M to 0.1 M, or0.01 M to 0.09 M, or 0.02 M to 0.09 M, or 0.03 M to 0.09 M, or 0.04 M to0.09 M, or 0.05 M to 0.09 M, or 0.06 M to 0.08 M. In some embodiments,the oxidizing agent comprises sodium bromate and is present in anaqueous fluid at a concentration in a range of 0.1 M to 0.5 M, or 0.1 Mto 0.4 M, or 0.1 M to 0.2 M, or 0.3 M to 0.4 M, or 0.15 M to 0.25 M.

In some embodiments, the oxidizing agent is characterized in that itrequires a threshold temperature to react with a salt of a compositiondescribed in this application. For instance, in some embodiments, anoxidizing agent at 1 atmosphere pressure requires a thresholdtemperature of at least 65° C., 70° C., 75° C., 80° C., 85° C., 90° C.,95° C., 100° C., 110° C., 120° C., 130° C., or 140° C. in order to reactwith the hydrofluoric acid generating precursor. In some embodiments,the oxidizing agent at 1 atmosphere pressure is characterized in that itrequires a threshold temperature in the range of 65° C. to 250° C. toreact with the hydrofluoric acid generating precursor. In someembodiments, the oxidizing agent at 1 atmosphere pressure ischaracterized in that it requires a threshold temperature greater thanambient temperature to react with the hydrofluoric acid generatingprecursor. It will be appreciated that in the presence of acceleratorssuch as low pH conditions, the reaction can be triggered to proceed atlower temperatures.

Examples of oxidizing agent and hydrofluoric acid generating precursorcombinations for use in accordance with one or more embodiments of thepresent disclosure include combinations of sodium bromate in combinationwith ammonium fluoride, -ammonium bifluoride, ammoniumhexafluorophosphate, or ammonium tetrafluoroborate.

The combination of the hydrofluoric acid generating precursor, oxidizingagent, ammonium containing compound, and nitrite containing compoundform a treatment fluid. The components of the treatment fluid areprovided to the sandstone formation to generate nitrogen gas, heat, andHF in-situ. In one or more embodiments, the components of the treatmentfluid comprise ammonium fluoride (NH₄F) as the hydrofluoric acidgenerating precursor, sodium bromate (NaBrO₃) as the oxidizing agent,sodium nitrite (NaNO₂) as the nitrite containing compound, and ammoniumchloride (NH₄Cl) as the ammonium containing compound. For clarity andconciseness, Reactions 1 through 3 are described using components of thetreatment fluid as delineated in the previous example compositions.However, it should be understood by a person of ordinary skill in theart that compounds of similar class of reactants will generally react ina similar way as the example reaction schemes shown in Reactions 1through 3.

A reaction between the ammonium containing compound and the nitritecontaining compound generates heat and nitrogen gas. An example of sucha reaction is provided in Reaction 1.NH₄Cl+NaNO₂→NaCl+2H₂O+N₂ (gas)+ΔH (heat)  Reaction 1

In typical usage, Reaction 1 results in generation of about 225kilocalories (Kcal) of heat per one liter (L) of reactants. Withoutwishing to be bound by theory, it is believed that the increasedpressure from nitrogen gas generation downhole may provide additionalenergy to flowback the well and prevent precipitation of any reactionproducts of HF and sandstone.

A follow-on reaction of the hydrofluoric acid generating precursor andthe oxidizing agent generates HF in-situ. However, the reaction requiresheating of the reactants to at least 300° F. (149.9° C.) to proceed at apressure of 50 pounds per square inch (PSI). It will be appreciated thatthe initiation temperature may be reduced with an elevation in pressure.While the temperature of the formation may be sufficient for thereaction to proceed, the heat generated in Reaction 1 providesadditional thermal energy to expedite initiation of the reaction of thehydrofluoric acid generating precursor and the oxidizing agent. Anexample reaction is provided in Reaction 2.12NH₄ ⁺+6BrO₃ ⁻→10H⁺+H₂+6N₂+Br₂+4Br⁻+18H₂O  Reaction 2

The reactants in the treatment fluid also may undergo an alternatereaction between the ammonium containing compound and the oxidizingagent. When the ammonium containing compound is ammonium chloride,reaction with the oxidizing agent generates hydrochloric acid (HCl). Thegeneration of HCl in-situ assists in maintaining an acidic pH at thesandstone formation. The HCl also helps keep the reaction productssoluble in the spent treatment fluid. Additionally, the reaction of theammonium containing compound and the oxidizing agent generatesadditional nitrogen gas which is beneficial in providing energy toflowback the well and prevent or remove any precipitation. This reactionis captured in the generic form of Reaction 2.

In one or more embodiments, ammonium bifluoride (NH₄HF₂) mayadditionally be provided downhole to generate additional HF. Theammonium bifluoride reacts with HCl to generate additional HF downholein accordance with Reaction 3 provided subsequently. The HCl may bepresent downhole as a product of Reaction 2. The HCl may also beprovided downhole alternatively or additionally as a feed of HCl pumpedfrom the surface.2HCl+NH₄HF₂→NH₄Cl+2HF  Reaction 3

One or both of the hydrofluoric acid generating precursor and theoxidizing agent comprise a degradable encapsulation. In someembodiments, the oxidizing agent is provided in an encapsulated form,for instance to delay its release. Encapsulated oxidizing agents arecommercially available and are known to those of ordinary skill in theart. Exemplary encapsulated oxidizing agents include sodium persulfate,potassium persulfate, sodium bromate and potassium bromate. In someembodiments, the hydrofluoric acid generating precursor is provided inan encapsulated form, for instance to delay its release. Encapsulationof one or both of the hydrofluoric acid generating precursor and theoxidizing agent prevents reaction of the oxidizing agent with thehydrofluoric acid generating precursor such that the oxidizing agent isconsumed prior to reaction with the ammonium containing compound, suchas reaction with NH₄Cl to generate HCl in accordance with Reaction 2.

When the methods of the present disclosure are utilized during hydraulicfracturing treatments, a synthetic sweet spot can be created, therebystimulating production and enabling maximum enhancement of gasproduction. A sweet spot is generally defined in this disclosure as thearea within a reservoir that represents the best production or potentialfor production. FIG. 1 is a schematic drawing of a wellbore used forhydraulic fracturing operations, where a fracturing fluid is injectedinto the wellbore 100 at a flow rate such that pressure is createdinside the wellbore to cause fractures 110 in the formation. Generally,the fracture 110 produced during hydraulic fracturing can extend deepinto the formation, as shown in the region of hydraulic fracturing 101.For example, as shown in FIG. 1 , the fracture 110 is shown to extendinto the formation to a fracture length 102. In various embodiments,this fracture length 102 can extend up to 100 meters, up to 50 meters,and up to 25 meters. Additionally, the hydraulic fracturing process canbe designed such that the fractures 110 extend outward from the wellborein multiple directions.

FIG. 2 shows the propagation of microfractures 112 within and extendingfrom the fractures 110 produced as a result of the hydraulic fracturingprocedure, thus creating sweet spots 116. Depending upon the reactantsand the volume of nitrogen gas produced therefrom, the microfractures112 can extend throughout a pseudo fracture width 118 from the fracture110 created during hydraulic fracturing. The pseudo fracture width 118represents the penetration depth of the microfractures 112 extendingfrom the fracture 110. FIG. 3 similarly shows an end view of the same.The microfractures 112 may additionally be generated or cleared offormation minerals in sandstone formations with the introduction of thehydrofluoric acid generated in accordance with this disclosure.

The release of nitrogen gas within the formation during the hydraulicfracturing operation forms additional microfractures 112 within theformation. With reference to FIG. 4 which provides an illustration of aformation subsequent to nitrogen gas creation, the wellbore 100 iswithin a sandstone formation 108 and a drill pipe 106 is positionedwithin the wellbore 100. Following a hydraulic fracturing process,fractures 110 exist within the sandstone formation 108. Acid andnitrogen gas generating fluids, such as the treatment fluid of thepresent disclosure may be injected into the sandstone formation 108where it migrates within the fractures 110 before produces nitrogen gas,heat, and hydrofluoric acid. The rapidly expanding nitrogen gas causesthe microfractures 112 to be created within the formation. The generatedmicrofractures 112 providing pathways for the hydrocarbons trappedwithin the formation to migrate and be recovered as well as fluidpathways for stimulation of the sandstone formation 108 with thehydrofluoric acid.

The present disclosure includes a variety of methods to provide thetreatment fluid deep into a horizontal well before reaction between theconstituent components of the treatment fluid is initiated resulting ingeneration of HF.

In one or more embodiments, the hydrofluoric acid generating precursor,the oxidizing agent, the ammonium containing compound, and the nitritecontaining compound are mixed together before being pumped downhole forinjection into the sandstone formation as one solution. It will beappreciated that one or both of the hydrofluoric acid generatingprecursor and the oxidizing agent may be encapsulated with a degradableencapsulation to reduce premature reaction. The treatment solutionformed from the hydrofluoric acid generating precursor, the oxidizingagent, the ammonium containing compound, and the nitrite containingcompound may remain stable until reaching an elevated temperatureexperienced downhole.

In further embodiments, the components of the treatment solution may beprovided to the sandstone formation as two or more separate solutions.Specifically, a first solution comprising the hydrofluoric acidgenerating precursor, the oxidizing agent, and the ammonium containingcompound and a second solution comprising the nitrite containingcompound may be provided downhole separately. The first solution and thesecond solution are combined downhole to initiate Reaction 1 between thenitrite containing compound and the ammonium containing compoundfollowed by initiation of Reaction 2. It will be appreciated that one orboth of the hydrofluoric acid generating precursor and the oxidizingagent may be encapsulated with a degradable encapsulation to preventpremature reaction. In one or more embodiments, the first solution isprovided downhole through a coiled tubing of the drilling string and thesecond solution is provided downhole through an annulus of the drillingstring. In one or more embodiments, the first and second solutions arereversed where the second solution is provided downhole through thecoiled tubing of the drilling string and the first solution is provideddownhole through the annulus of the drilling string.

In one or more embodiments, the components of the treatment solution maybe injected or squeezed into the sandstone formation in a sequentialmanner. The hydrofluoric acid generating precursor and the oxidizingagent may be injected into the sandstone as a first injection andsubsequently the nitrite containing compound may be injected into thesandstone formation as a second injections. The ammonium containingcompound may be provided as part of the first injection, the secondinjection, or both injections. For example, NH₄F and NaBrO₃ may besqueezed into the sandstone formation and then subsequently NaNO₂ andNH₄Cl may be provided downhole and squeezed into the sandstoneformation. Similarly, NH₄F, NaBrO₃, and NH₄Cl may be squeezed into theformation and subsequently only NaNO₂ is provided downhole and squeezedinto the sandstone formation. It will be appreciated that the order maybe reversed such that NaNO₂ is initially provided and squeezed into thesandstone formation followed by a solution comprising NH₄F, NaBrO₃, andNH₄Cl. It will be appreciated that one or both of the hydrofluoric acidgenerating precursor and the oxidizing agent may be encapsulated with adegradable encapsulation to reduce premature reaction.

The location and rate of HF generation may be affected by a variety ofprocess parameters. For example, the pH of the treatment fluid, thedownhole temperature and by proxy the temperature of the treatmentfluid, and the downhole pressure each affect the reaction rate, thereaction triggering temperature, or both of one or more of the reactionsto generate HF downhole.

The downhole pressure at the location of the treatment solution mayaffect the initiation temperature of Reaction 1. With reference to FIG.5 , the effect of initial pressure on the initiation temperature ofReaction 1 is shown. As the downhole pressure increases the initiationtemperature of Reaction 1 generally decreases. However, it will beappreciated that for pressures in excess of approximately 300 pounds persquare inch (psi), an increase in pressure does not have a correspondingeffect on the initiation temperature of Reaction 1. In variousembodiments, the downhole pressure in the reservoir may be 300 to 15000psi, 500 to 12000 psi, 1000 to 10000 psi, or 3000 to 8000 psi.

The pH of the treatment solution also may affect the initiationtemperature of Reaction 1 and Reaction 2. With reference to FIG. 6 , theeffect of pH on the initiation temperature of Reaction 1 is shown at areservoir pressure of 500 psi. At that pressure, an increase in the pHresults in a corresponding increase in the initiation temperature ofReaction 1. At a pH of 6 the initiation temperature of Reaction 1 isapproximately 122° F. (50° C.), at a pH of 8 the initiation temperatureof Reaction 1 is approximately 150° F. (65.6° C.), and at a pH of 9 theinitiation temperature of Reaction 1 is approximately 182° F. (83.3°C.). As such, the pH of the treatment solution may be adjusted for thespecific temperature and pressure conditions of each reservoir to allowfor positioning of the treatment solution within the formation beforeReaction 1 progresses. In various embodiments, the pH may be in therange of 6 to 10, 6 to 9, 7 to 8, 8 to 9, 6 to 8, or 7 to 9 to accountfor distinct downhole pressures and temperatures unique to each well.

In another embodiment, at least the ammonium containing compound and thenitrite containing compound of the treatment fluid are provided in anacid generating solution comprising a degradable acid precursor. Theacid generating solution may be injected into a sandstone formation oras part of a hydraulic fracturing procedure. The degradable acidprecursor may be soluble and compatible with the ammonium containingcompound and the nitrite containing compound, and the resulting reactionproducts. The degradable acid precursor degrades and releases acidwithin the formation reducing the pH to less than a reaction initiationthreshold pH. Specifically, the generated acid reduces the pH of theresulting solution over time such that the injected fluids have time toenter into the formation, and migrate into the fractures created by thehydraulic fracturing process before the pH is reduced to less than thereaction initiation threshold pH. The reaction initiation threshold pHrepresents the pH at which reaction between the ammonium containingcompound and the nitrite containing compound occurs at the presenttemperature and pressure. In one or more embodiments, the reactioninitiation threshold pH is less than about 7.0 for a reservoir pressureof 500 psi and a reservoir temperature of approximately 135° F. (57.3°C.). It will be appreciated that the reaction initiation threshold pHmay vary based on the reservoir temperature, the reservoir pressure, orboth. Example acid generating precursors include acetates, includingmethyl acetates and ethyl acetates. At typical formation temperatures of100 to 350° F., methyl acetate hydrolyzes and releases acetic acid. Thistakes place inside the formation after injection of the fluids. Incertain embodiments, approximately 5% by volume of the acid generatingprecursor as a 0.1 molar solution may be included with the ammoniumcontaining compound and the nitrite containing compound.

It will be appreciated that the initiation temperature of Reaction 1 isapproximately 500° F. (260° C.) at a pH of 10 allowing for triggeringprogression of Reaction 1 based on adjustments to only the pH.Specifically, at typical formation temperatures of 100 to 350° F.,utilization of a treatment solution having an initial pH greater than 10ensures Reaction 1 does not proceed until the buffer degrades togenerate a pH of the treatment solution less than the reactioninitiation threshold pH.

In one or more embodiments, at least one of the ammonium containingcompound and the nitrite containing compound is encapsulated with aself-degradable coating. The coating provides a temporary barrierbetween the ammonium containing compound, the nitrite containingcompound, or both, such that they are unable to react in accordance withReaction 1 before degradation of the coating.

The material of the degradable coating and the thickness of thedegradable coating each affect the delay in releasing the reactants forReaction 1 downhole. Specifically, the speed of removal of thedegradable coating determines the timing of the availability of both theammonium containing compound and the nitrite containing compound forreaction. A thicker degradable coating would naturally require a longerperiod of time in an erosive environment before penetration,dissipation, and removal of the degradable coating from the ammoniumcontaining compound or the nitrite containing compound. Similarly,differing the distinct materials forming the degradable coating wouldprovide different time horizons in each erosive environment beforeavailability of the ammonium containing compound and the nitritecontaining compound for reaction in accordance with Reaction 1.Specifically, the water solubility or heat degradation, for example, ofcarboxymethyl cellulose and polyvinyl alcohol may be distinct allowingfor tuning of the time delay before progression of Reaction 1.

Suitable encapsulation materials for the degradable coating of theammonium containing compound or the nitrite containing compound caninclude hydrated polymers, such as guar, chitosan, and polyvinylalcohol. In certain embodiments, the previously noted hydrated polymerencapsulation materials may be used as the encapsulant for the nitritecontaining compound, such as sodium nitrite. In alternate embodiments,binders, such as carboxymethyl cellulose or xanthan, can be used as anencapsulant. In certain embodiments, the carboxymethyl cellulose orxanthan may be the encapsulant for the ammonium containing compound,such as ammonium chloride. The heat of the formation, presence of acid,or presence of water may collectively play a role in the erosion ordegradation of the encapsulating material, thereby releasing thereactants. It will be appreciated that the degradable encapsulation ofone or both of the hydrofluoric acid generating precursor and theoxidizing agent may be of similar nature to that disclosed for thedegradable coating of the ammonium containing compound or the nitritecontaining compound.

The extent of application of the degradable coating may also affect theprogression of Reaction 1. In one or more embodiments, 30 to 100 weightpercent (wt. %) of one or more of the ammonium containing compound andthe nitrite containing compound are encapsulated. In variousembodiments, 40 to 95 wt. %, 50 to 90 wt. %, or 60 to 85 wt. % of one ormore of the ammonium containing compound and the nitrite containingcompound are encapsulated. The greater the percentage of the one or moreof the ammonium containing compound and the nitrite containing compoundwhich are encapsulated, the slower Reaction 1 will progress as thereaction is limited by the availability of reactants. Specifically, when100 wt. % of one or more of the ammonium containing compound and thenitrite containing compound are encapsulated, the reaction rate ofReaction 1 is limited by the erosion rate of the degradable coating andthe commensurate rate of availability of the ammonium containingcompound and the nitrite containing compound. Conversely, when 30 wt. %of one or more of the ammonium containing compound and the nitritecontaining compound are encapsulated Reaction 1 may progress with 70 wt.% of the reactants and is only limited with the remaining 30 wt. %. Itwill be appreciated that the degradable encapsulation of one or both ofthe hydrofluoric acid generating precursor and the oxidizing agent maybe provided at a similar weight percentage as that disclosed for thedegradable coating of the ammonium containing compound or the nitritecontaining compound.

Adjusting the parameters of the degradable coating allows the treatmentfluid to be tunable to specific reservoir conditions. A delay asdetermined by the specific well conditions may be created beforeavailability of reactions for Reaction 1. For example, a delay of 3 to12 hours may be achieved to allow sufficient time for the treatmentfluid to be placed downhole and deep within a horizontal well beforegeneration of HF and associated interaction with the sandstone formationto remove silica and silicate minerals.

The concentration of HF in the sandstone formation affects the rate ofsilica and silicate mineral removal. The HF dissolves silica andsilicate minerals, such as aluminosilicate, while HCl or other strongmineral acid helps keep the reaction products soluble in the spentsolution. As the HF is generated in-situ at the site of the sandstoneformation the HF does not undergo a potency decrease as a result ofinteraction with other species during the transfer from the surface tothe sandstone formation. In one or more embodiments, the concentrationof HF at the sandstone formation is from 0.5 to 10 wt. %. In variousfurther embodiments, the concentration of HF at the sandstone formationis from 0.8 wt. % to 8 wt. %, 0.9 wt. % to 5 wt. %, or 1 wt. % to 3 wt.%.

Generation of HF downhole removes the need for handling HF at thesurface of the wellbore allowing for a greater concentration of HFwithout the associated handling risks. Further, generation of HF in-situalleviates exposure of the drill string components to the HF duringtransit downhole allowing for greater concentrations of HF at thesandstone formation without the increased corrosion risks from HFexposure.

Reaction of the HF with the silica and silicate materials results in theHF being spent before flowback into the wellbore. After stimulationoperations the resulting slurry of the spent HF and the removedsilica/silicate present downhole must be removed from the wellbore. Inone or more embodiments, the slurry is squeezed back into the formationfor retention and disposal. In further embodiments, the slurry is pumpedfrom the wellbore and flowed to a pit at the surface for retention,processing, and disposal. Any solids generated during the formationstimulation operation may be removed during the stimulation operationthrough the motive lifting force of generated nitrogen gas produced bythe reaction of the nitrite containing compound and the ammoniacontaining compound in Reaction 1.

The methods and compositions of the present disclosure may also beapplied to deep carbonate formation stimulation in hydrocarbonreservoirs. Specifically, in deep carbonate formation stimulation,calcite (CaCO₃) and dolomite (CaMg(CO₃)₂) are removed from the deepcarbonate formation to allow flow of trapped hydrocarbon reserves. Thecalcite and dolomite may be removed with carbonite acidizing where HClis reacted with the calcite and dolomite. It will be appreciated thatReaction 2 of the present disclosure provides HCl in-situ and thus maybe used for deep carbonate formation stimulation. Specifically, theammonium containing compound, the nitrite containing compound and theoxidizing agent may each be provided to allow Reactions 1 and 2 toprogress and generate HCl. In-situ and delayed production of HCl allowsfor deeper carbonate formation stimulation in each fracture thantraditional methods of providing HCl from the surface as the HCl is notfully reacted and spent before reaching deep fractures.

It will be appreciated that the present methods and compositions maysimultaneously stimulate sandstone formations and deep carbonateformations in a single procedure. This is advantageous in operationswith both sandstone and carbonate formations.

EXAMPLES

Testing was completed to verify the progression of Reaction 2 andgeneration of HF. An aqueous solution of 0.75 grams (g) sodium bromateand 0.37 g of ammonium fluoride in 25 milliliters (ml) of water wasprepared. A similar solution of 0.75 grams (g) sodium bromate and 0.57 gof ammonium bifluoride in 25 milliliters (ml) of water was alsoprepared. The aqueous solution was placed in a 125 ml autoclave reactorand an initial pH of the aqueous solution was measured. The autoclavereactor was sealed and placed in an oven at 150° C. for 8 hours (h). Theautoclave reactor was then cooled to room temperature and a final pH wasmeasured. It was determined that the pH of the aqueous solution droppedto 2-3, whereby acid-base titration results yielded an approximately 8.4mmol of acid, clearly indicating the formation of acid.

Having demonstrated feasibility of Reaction 2 for the generation of HF,a field test of Reaction 1 for the generation of heat and pressure wascompleted. Sodium nitrite and ammonium chloride, in accordance withReaction 1, were pumped separately downhole and into the formation.Specifically, sodium nitrite was pumped through the coiled tubing of thedrilling string and ammonium chloride was pumped through the annulus ofthe drilling string. With reference to FIG. 7 , the downhole pressureincreased from approximately 2600 psi to approximately 3800 psi afterinjection of the reactants and initiation of Reaction 1 to generatenitrogen gas (approximately 14:37:47). The pressure was measured with agauge positioned at the wellhead. Similarly, the downhole temperatureincreased from approximately 100° F. (37.8° C.) to approximately 420° F.(215.6° C.) after injection of the reactants and initiation of Reaction1 to generate heat in the exothermic reaction. The temperature wasmeasured with a gauge positioned within the wellbore at the well bottom.

With continued reference to FIG. 7 , it is noted that there is anapproximately 3 hour delay between injection of the reactants and thespike in temperature. The approximately 3 hour delay is attributed tothe experimental protocol where the sodium nitrite and ammonium chloridewere continuously squeezed into the formation for the first 3 hoursafter injection. During the period where the sodium nitrite and ammoniumchloride were squeezed into the formation, Reaction 1 was proceedingdeep within fractures and microfractures of the formation away from thetemperature gauge in the wellbore and as such the temperature gauge wasunable to measure the temperature increase of the solution within theformation. Upon completion of the pumping of the fluid with thereactions into the formation, the fluid was able to flow back. Thebackflowing fluid, having been heated for up to 3 hours by progressingReaction 1 during the period of squeezing into the formation, returns tothe wellbore and the temperature gauge in a hot state.

Upon completion of Reaction 1 to generate heat within the formation, theproducts and residual reactants were displaced with water pumped intothe formation. Upon termination of pumping, flowback occurred from theformation of the heated fluid generating a second peak in temperature inFIG. 7 .

It should now be understood the various aspects of the method andassociated treatment fluid for stimulating production of hydrocarbonsfrom a sandstone formation are described and such aspects may beutilized in conjunction with various other aspects.

In a first aspect, the disclosure provides a method for stimulatingproduction of hydrocarbons from a sandstone formation. The methodcomprises the steps of: injecting a stimulation fluid into the sandstoneformation, the stimulation fluid comprising a hydrofluoric acidgenerating precursor and an oxidizing agent, where one or both of thehydrofluoric acid generating precursor and the oxidizing agent comprisea degradable encapsulation; injecting an ammonium containing compoundinto the sandstone formation; injecting a nitrite containing compoundinto the sandstone formation; maintaining the stimulation fluid, theammonium containing compound, and the nitrite containing compound in thesandstone formation. The stimulation fluid, the ammonium containingcompound, and the nitrite containing compound are maintained in thesandstone formation to initiate reaction of the ammonium containingcompound and the nitrite containing compound to generate heat andnitrogen gas, where upon generation of heat within the formation anddegradation of the degradable encapsulation, the hydrofluoric acidgenerating precursor and the oxidizing agent react to form hydrofluoricacid in-situ, and dissolve silica and silicate minerals to stimulate thesandstone formation.

In a second aspect, the disclosure provides the method of the firstaspect, in which the hydrofluoric acid generating precursor comprisesNH₄F, NH₄HF₂, or both NH₄F and NH₄HF₂.

In a third aspect, the disclosure provides the method of the first orsecond aspects, in which the oxidizing agent comprises an agent selectedfrom the group consisting of a peroxide, a persulfate salt, apermanganate salt, a bromate salt, a perbromate salt, a chlorate salt, achlorite salt, a perchlorate salt, a hypochlorite salt, an iodate salt,a periodate salt, and mixtures thereof.

In a fourth aspect, the disclosure provides the method of the thirdaspect, in which the oxidizing agent comprises sodium bromate orpotassium bromate.

In a fifth aspect, the disclosure provides the method of any of thefirst through third aspects, in which the nitrite containing compoundcomprises a nitrite salt.

In a sixth aspect, the disclosure provides the method of the fifthaspect, in which the nitrite salt comprises NaNO₂.

In a seventh aspect, the disclosure provides the method of any of thefirst through sixth aspects, in which the ammonium containing compoundcomprises one or more of ammonium hydroxide, ammonium chloride, ammoniumbromide, ammonium nitrate, ammonium nitrite, ammonium sulfate, andammonium carbonate.

In an eighth aspect, the disclosure provides the method of the seventhaspect, in which the ammonium containing compound comprises NH₄Cl.

In a ninth aspect, the disclosure provides the method of any of thefirst through eighth aspects, in which at least one of the ammoniumcontaining compound and the nitrite containing compound are encapsulatedwith a degradable coating such that reaction between the ammoniumcontaining compound and the nitrite containing compound is delayed.

In a tenth aspect, the disclosure provides the method of any of thefirst through ninth aspects, in which a first solution comprising thehydrofluoric acid generating precursor, the oxidizing agent, and theammonium containing compound and a second solution comprising thenitrite containing compound are provided downhole separately.

In an eleventh aspect, the disclosure provides the method of the ninthaspect, in which the hydrofluoric acid generating precursor, theoxidizing agent, the ammonium containing compound, and the nitritecontaining compound are mixed together before being pumped downhole forinjection into the sandstone formation as one solution.

In a twelfth aspect, the disclosure provides the method of any of thefirst through tenth aspects, in which the first solution or the secondsolution is provided downhole through a coiled tubing of the drillingstring and the other of the first solution or the second solution isprovided downhole through an annulus of the drilling string.

In a thirteenth aspect, the disclosure provides the method of any of thefirst through ninth aspects, in which the hydrofluoric acid generatingprecursor and the oxidizing agent are injected into the sandstoneformation as a first injection and subsequently the nitrite containingcompound is injected into the sandstone formation as a second injection.The ammonium containing compound is provided with one or both of thefirst injection and the second injection, thereby activating thereaction of the ammonium containing compound and the nitrite containingcompound to generate heat and activate the stimulation fluid to generatehydrofluoric acid in-situ.

In a fourteenth aspect, the disclosure provides the method of the ninthaspect, in which at least one of the ammonium containing compound andthe nitrite containing compound is encapsulated in a polymer coating.

In a fifteenth aspect, the disclosure provides the method of any of thefirst through fourteenth aspects, in which at least one of thehydrofluoric acid generating precursor and the oxidizing agent isencapsulated in a polymer coating.

In a sixteenth aspect, the disclosure provides the method of thethirteenth or fourteenth aspects, in which the polymer coating comprisesa hydrated polymer.

In a seventeenth aspect, the disclosure provides the method of the ninthor fourteenth aspects, in which at least 30 percent by weight of one ormore of the ammonium containing compound and the nitrite containingcompound are encapsulated.

In an eighteenth aspect, the disclosure provides the method of any ofthe first through seventeenth aspects, in which at least 30 percent byweight of one or more of the hydrofluoric acid generating precursor andthe oxidizing agent are encapsulated.

In a nineteenth aspect, the disclosure provides the method of any of thefirst through eighteenth aspects, in which at least the ammoniumcontaining compound and the nitrite containing compound are provided inan acid generating solution that releases hydrogen ions and reduces thepH of the resulting solution to less than a reaction initiationthreshold pH to initiate reaction between the ammonium containingcompound and the nitrite containing compound.

In a twentieth aspect, the disclosure provides the method of thenineteenth aspect, in which the reaction initiation threshold pH is 7.0.

In a twenty-first aspect, the disclosure provides the method of theeighth aspect, in which the oxidizing agent and the NH₄Cl react to formHCl.

In a twenty-second aspect, the disclosure provides the method of thetwenty-first aspect, in which the method further comprises injectingammonium bifluoride into the sandstone formation, the ammoniumbifluoride reacting with HCl to form HF.

In a twenty-third aspect, the disclosure provides a treatment fluid foruse in stimulating sandstone formations. The treatment fluid comprises astimulation fluid, the stimulation fluid comprising a hydrofluoric acidgenerating precursor and an oxidizing agent, where one or both of thehydrofluoric acid generating precursor and the oxidizing agent comprisea degradable encapsulation; ammonium-based salt, and a nitritecontaining compound. The ammonium containing compound and the nitritecontaining compound are operable to react and generate heat and nitrogengas and the hydrofluoric acid generating precursor and the oxidizingagent react are operable to react to form hydrofluoric acid.

In twenty-fourth aspect, the disclosure provides the treatment fluid ofthe twenty-third aspect, in which the hydrofluoric acid generatingprecursor comprises NH₄F, the oxidizing agent comprises sodium bromate,the nitrite containing compound comprises a nitrite salt, and theammonium containing compound comprises one or more of ammoniumhydroxide, ammonium chloride, ammonium bromide, ammonium nitrate,ammonium nitrite, ammonium sulfate, and ammonium carbonate.

In a twenty-fifth aspect, the disclosure provides the treatment fluid ofthe twenty-third or twenty-fourth aspects, in which at least one of theammonium containing compound and the nitrite containing compound areencapsulated with an degradable coating such that reaction between theammonium containing compound and the nitrite containing compound isdelayed.

In a twenty-sixth aspect, the disclosure provides the treatment fluid ofany of the twenty-third through twenty-sixth, in which the treatmentfluid additionally comprises ammonium bifluoride.

It should be apparent to those skilled in the art that variousmodifications and variations can be made to the described embodimentswithout departing from the spirit and scope of the claimed subjectmatter. Thus, it is intended that the specification cover themodifications and variations of the various described embodimentsprovided such modifications and variations come within the scope of theappended claims and their equivalents.

The singular forms “a”, “an” and “the” include plural referents, unlessthe context clearly dictates otherwise.

Throughout this disclosure ranges are provided. It is envisioned thateach discrete value encompassed by the ranges are also included.Additionally, the ranges which may be formed by each discrete valueencompassed by the explicitly disclosed ranges are equally envisioned.

As used in this disclosure and in the appended claims, the words“comprise,” “has,” and “include” and all grammatical variations thereofare each intended to have an open, non-limiting meaning that does notexclude additional elements or steps.

As used in this disclosure, terms such as “first” and “second” arearbitrarily assigned and are merely intended to differentiate betweentwo or more instances or components. It is to be understood that thewords “first” and “second” serve no other purpose and are not part ofthe name or description of the component, nor do they necessarily definea relative location, position, or order of the component. Furthermore,it is to be understood that that the mere use of the term “first” and“second” does not require that there be any “third” component, althoughthat possibility is contemplated under the scope of the presentdisclosure.

What is claimed is:
 1. A treatment fluid for use in stimulatingsandstone formations, the treatment fluid comprising: a stimulationfluid, the stimulation fluid comprising a hydrofluoric acid generatingprecursor and an oxidizing agent, where the hydrofluoric acid generatingprecursor comprises a degradable encapsulation; ammonium-based salt; anda nitrite containing compound; where the ammonium-based salt and thenitrite containing compound are operable to react and generate heat andnitrogen gas and the hydrofluoric acid generating precursor and theoxidizing agent react are operable to react to form hydrofluoric acid.2. The treatment fluid of claim 1, where the hydrofluoric acidgenerating precursor comprises NH₄F, NH₄HF₂, or both NH₄F and NH₄HF₂,the oxidizing agent comprises sodium bromate, the nitrite containingcompound comprises a nitrite salt, and the ammonium-based salt comprisesone or more of ammonium hydroxide, ammonium chloride, ammonium bromide,ammonium nitrate, ammonium nitrite, ammonium sulfate, and ammoniumcarbonate.
 3. The treatment fluid of claim 2, where the oxidizing agentcomprises sodium bromate.
 4. The treatment fluid of claim 2, where thenitrite containing compound comprises NaNO₂.
 5. The treatment fluid ofclaim 2, where the ammonium containing compound comprises NH₄Cl.
 6. Thetreatment fluid of claim 2, where the hydrofluoric acid generatingprecursor comprises NH₄F.
 7. The treatment fluid of claim 2, where thehydrofluoric acid generating precursor comprises NH₄F, the oxidizercomprises sodium bromate, the nitrite containing compound comprisesNaNO₂, and the ammonium containing compound comprises NH₄Cl.
 8. Thetreatment fluid of claim 1, where the oxidizing agent comprises an agentselected from the group consisting of a peroxide, a persulfate salt, apermanganate salt, a bromate salt, a perbromate salt, a chlorate salt, achlorite salt, a perchlorate salt, a hypochlorite salt, an iodate salt,a periodate salt, and mixtures thereof.
 9. The treatment fluid of claim1, where at least one of the ammonium-based salt and the nitritecontaining compound are encapsulated with a degradable coating.
 10. Thetreatment fluid of claim 9, where at least 30 percent by weight of oneor more of the ammonium containing compound and the nitrite containingcompound are encapsulated.
 11. The treatment fluid of claim 2, where thetreatment fluid additionally comprises ammonium bifluoride.
 12. Thetreatment fluid of claim 1, where the oxidizing agent is present in thestimulation fluid at a concentration in the range of 1.0 M to 4.0 M. 13.The treatment fluid of claim 9, where the degradable coating comprises ahydrated polymer.
 14. The treatment fluid of claim 13, where thehydrated polymer comprises guar, chitosan, or polyvinyl alcohol.
 15. Thetreatment fluid of claim 9, where the degradable coating comprisescarboxymethyl cellulose.
 16. The treatment fluid of claim 9, where thedegradable coating comprises xanthan.
 17. The treatment fluid of claim1, where the degradable encapsulation comprises a hydrated polymer. 18.The treatment fluid of claim 1, where the degradable encapsulationcomprises carboxymethyl cellulose.
 19. The treatment fluid of claim 1,where the degradable encapsulation comprises xanthan.
 20. The treatmentfluid of claim 17, where the hydrated polymer comprises guar, chitosan,or polyvinyl alcohol.